Virtual power plant companies win contracts through three routes: a utility program or RFP, where the utility pays for enrolled capacity; wholesale market participation as a registered aggregator under FERC Order 2222; and bring-your-own-device programs, where customers enroll their own batteries and thermostats. Every buyer asks for the same proof: kilowatts measured on dispatch.

Which buyer pays on each route, and what do they check?

The utility pays on the first route and the ISO or RTO market on the second. On the third, the customer signs up and a utility or market pays. The Department of Energy's January 2025 update counts 33 GW of VPP capacity across North America and sets a 2030 target of 80 to 160 GW, enough to serve 10 to 20% of peak load.

Route Buyer What they need to see Milestone or timeline
Utility program or RFP Utility program manager, backed by the state commission A commission-approved program, enrolled kW by area, dispatch on the utility's notice, settlement from meter or device data Xcel's Colorado aggregator program, approved December 15, 2025, targets 125 MW over five years through a competitive bid (Colorado PUC, January 2026)
Wholesale market aggregator ISO or RTO, plus the distribution utility A registered aggregation of at least 100 kW, metering and telemetry to market rules, distribution utility sign-off ISO-NE opens registration on November 1, 2026 (ISO-NE, October 2026); PJM moves to February 2029 (PNNL, September 2025)
Bring your own device Customer, then the paying utility program Device compatibility, a clear payment, one enrollment step National Grid launched its device program in under four months (DOE, January 2025)

How do you win a utility program or RFP?

Go where a regulator has told the utility to buy VPP capacity, then show the program manager you can enroll and dispatch at the size the order sets.

  • Colorado: a May 2024 law, SB24-218, requires Xcel Energy to submit a VPP plan (DOE, January 2025). The commission approved the state's first aggregator VPP program on December 15, 2025, with 125 MW of new resources over five years and a competitive bid for companies that manage the networks (Colorado PUC, January 2026).
  • Virginia: a law signed May 2, 2025 told Dominion Energy to propose a pilot of up to 450 MW, with incentives for at least 15 MW of residential batteries, and lets customers enroll through a third-party aggregator (Utility Dive, May 2025). Dominion now states that the SCC has approved the pilot (Dominion, October 2026), and WHRO reported in June 2026 that it runs through July 2028.
  • Illinois: the governor signed the Clean and Reliable Grid Affordability Act on January 8, 2026, with a target of 3 GW of grid-scale storage by 2030 (Utility Dive, January 2026). In June 2026 the ICC approved ComEd's and Ameren's scheduled-dispatch VPP tariffs with a performance-based annual incentive (DSIRE Insight, July 2026).

The utility also needs a vendor that asks for little integration work. National Grid built its multi-device program in under four months with less than $500,000 of upfront investment, and it now provides up to 250 MW of peak shaving (DOE, January 2025). A National Grid employee sends dispatch instructions through the vendor's web portal. Pitch that shape: a portal and a dispatch notice, with no IT project. For the commission steps, read how DERMS vendors get a utility pilot approved.

When does wholesale market participation make sense?

It makes sense where the ISO runs a live aggregation model. Today that means CAISO, then ISO New England from the start of November, with New York close behind. PJM and MISO come later, on the dates below.

FERC approved Order 2222 in September 2020, and by January 2025 DOE reported that CAISO and ISO-NE had fully complied. Current dates by market:

The second buyer on this route is the distribution utility. Order 2222 sets a 60-day utility review, and in PJM that splits into a 15-day capability review and a 45-day reliability review (PNNL, September 2025). If you also build front-of-meter storage, read what FERC Order 2023 changes for energy startups.

How do bring-your-own-device programs fit?

Bring-your-own-device programs are how most VPP companies collect the kilowatts they then sell on the first two routes. National Grid's program is this model (DOE, January 2025). In Illinois, batteries that receive the state's storage rebates must join the scheduled-dispatch tariff (DSIRE Insight, July 2026).

Some utilities own the fleet instead. Green Mountain Power has run a leased-battery program since 2020, while LUMA in Puerto Rico draws over 10 MW of peaking capacity from customer batteries without a DERMS or smart meters (DOE, January 2025). Ask early whether the utility wants to own devices or pay for performance. The answer decides whether you sell software, enrollment or both.

What M&V, telemetry and accreditation proof do buyers check?

Buyers check three things: that you can prove each kilowatt against a baseline, that you report at the market's telemetry interval, and that your capacity keeps its accredited value under the market's availability rules. Rules differ by market:

  • NYISO requires six-second telemetry for every DER of at least 100 kW (DOE, January 2025).
  • PJM allows one-minute scans for non-regulation resources and exempts DERs under 10 MW from telemetry (DOE, January 2025).
  • ISO-NE requires actual telemetry from all assets, while CAISO, NYISO, PJM and SPP accept calculated readings from samples (DOE, January 2025).
  • PJM accredits demand response on availability from 10am to 10pm in summer and 6am to 9pm in winter, which derates resources that could perform outside those windows (DOE, January 2025).

Baselines need utility interval data, and the same DOE report notes that most utilities limit third-party access to it. Build this evidence pack before the first buyer meeting:

  1. Enrolled kW by utility zone and market node, by device type, with customer consent records.
  2. The baseline method for each buyer, named in its own terms.
  3. Event history: requested kW against delivered kW, per event.
  4. Telemetry interval and data path, matched to the target market.
  5. A signed data-access process with each distribution utility.
  6. Capacity value recalculated under the buyer's availability windows.
  7. A site list ready for the distribution utility's review.

Where should a VPP company start?

Start with mandated utility programs in Colorado, Virginia and Illinois, the ERCOT pilot, and the ISO-NE and NYISO markets. Treat PJM and MISO as later pipeline. The field is crowded: we count about 700 grid software, VPP, demand response and DER vendors with 21 to 500 staff (our data, Oct 2026). Most of those vendors chase the same program managers, so name the regulatory affairs lead and the distribution planner at each target utility as well. Our Outbound service books those meetings for companies that sell to large institutions.

To pick the route and the first buyer for your product, start with The Diagnostic.